Completion Of Horizontal Wells Research Articles

Mathematical Modeling of Prediction of Horizontal Wells with Gravel Pack Combined with ICD in Bottom-Water Reservoirs

During the development of horizontal wells in bottom-water reservoirs, the strong heterogeneity of reservoir permeability leads to premature bottom-water breakthroughs at locations with high permeability in the horizontal wellbore, and the water content rises rapidly, which seriously affects production. To cope with this problem, a new technology has emerged in recent years that utilizes gravel filling to block the flow in the annulus between the horizontal well and the borehole and utilizes the Inflow Control Device (ICD) completion tool to carry out segmental water control in horizontal wells. Unlike conventional horizontal well ICD completions that use packers for segmentation, gravel packs combined with ICD completions break the original segmentation routine and increase the complexity of the production dynamic simulation. In this paper, the flow in different spatial dimensions, such as reservoirs, gravel-packed layers, ICD completion sections, and horizontal wellbores, is modeled separately. Furthermore, the annular pressures at different locations are used as the solution variable for the coupled solution, which realizes the prediction of oil production, water production, and the water content of gravel packs combined with ICD completion of horizontal wells. The model is used to calculate the effects of different crude oil viscosities, different reservoir permeabilities, different permeabilities of gravel-packed layers, and different development stages on the water control effects of gravel packs combined with ICD completions and conventional ICD completions under field conditions.

Performance of Horizontal Wells Completed in Unconsolidated Sand: Case Study Niger-Delta

Drilling and completion of horizontal wells have been proven to be a productive and profitable project, in comparison with the performance of the conventional vertical wells. However, in Nigeria there are very few application of horizontal wells as open-hole, this is largely due to the unconsolidated nature of Niger-Delta sands. This study examined the completion of open-hole horizontal wells with a case study of a field which is located within the Niger-Delta region in Nigeria. Two (2) wells which have been successfully drilled and completed were sampled. To achieve this, the performance of the completion option was examined using an analytical approach. This implored the Joshi’s model and Vogel’s equation to construct the Inflow Performance Relationship (IPR) plot. The vertical lift performance (VLP) was considered by employing Gilbert’s method. From the combined plots, the optimum operating condition of the wells indicated that well A has a productivity index of 1.039 Stb/day/psi with a maximum flow rate of 3250 Stb/day, while well B has a productivity index of 1.156 Stb/day/psi and maximum rate of 3370 Stb/day. The results show that horizontal well projects executed in fields within the Niger-Delta region can be expected to produce at good rates as obtained in other regions of the world. With the production capacity shown by these wells, improved conventional ultimate recovery is assured. Keywords: Horizontal Well, Inflow Performance Relationship, Open-hole, Productivity index, and Vertical Lift Performance. DOI: 10.7176/JEES/11-10-07 Publication date: October 31 st 2021

ROP Improvement Technologies for Large-Cluster Horizontal Shale Oil Wells in the Changqing Oilfield

Large frictional torque, backpressure during slide drilling, low rate of penetration (ROP), poor recognition of reservoirs by geosteering, and other problems are encountered during the drilling of large-cluster horizontal shale oil wells in the Changqing Oilfield. In this regard, this paper studied the multi-layer layout of large-cluster horizontal wells, large offset design, three-dimensional well trajectory control technology, and drilling tools for ROP improvement. Technical breakthroughs were made in the optimized deployment of well patterns/sequences, the anti-collision design between dense well group trajectories, the completion of horizontal well in one trip, the evaluation and accurate control of reservoirs while drilling, and the safe drilling in water injection areas,etc. Finally, the ROP improvement technologies for large-cluster horizontal shale oil wells in the Changqing Oilfield were developed. The field tests of the technologies were carried out in large-cluster well platforms, the Platform Hua H40 and the Platform Hua H60. The maximum number of horizontal wells in the well clusters was 22, with an average drilling cycle of 18.9 d, which was shortened by 7.5% after using the technologies. The research and field application demonstrate that the ROP improvement technologies for large-cluster horizontal wells have realized the large-scale development of shale oil in the Changqing Oilfield, promoting the construction of the Longdong National Shale Oil Demonstration Base.

Induced seismicity risk management: The problem of disappearing faults

The risk of anthropogenic earthquakes created by fluid injection and completion of horizontal wells is managed using maps of recent seismicity and by creating buffer zones around previously mapped faults. In Madison and Fayette Counties, Ohio, faults were identified in 1969 using analogue paper-recorded seismic reflection technology. These faults were located primarily by mapping a prominent “Conasauga reflector” from a shale within the subsurface Cambrian section. The faults were associated with an apparent abrupt increase of the regional dip to the east. The appearance of these faults on subsequent structural maps guides regulation of horizontal drilling activity in Ohio. A time-migrated, nominal 60-fold, mini-hole-sourced, seismic section using a digital recorder with 24-bit sigma delta technology was acquired over what was reported to be the best constrained of these faults; it revealed no detectable fault or significant change in the regional dip. A synthetic seismogram derived from a sonic log acquired at a nearby well enabled identification of a seismic facies change that was likely mistaken for faulting using the earlier technology. Regulations should consider acquisition parameters and vintage of seismic surveys used to identify faults for induced seismicity risk management.

Study on the Construction and Performance of Completion Fluid System in Fractured Carbonate Reservoir

There are microfractures and fractures in the carbonate formation of M oilfield, which are easy to cause collapse and borehole instability. On the basis of the liquefiable cleanflo drilling fluid system for open hole completion of horizontal wells designed in the early stage, this paper has carried out the research work of matching acidizing completion fluid system. In this paper, the influence factors, cleaning ability, compatibility, acidizing situation and protection effect of acidizing completion fluid system are evaluated in laboratory. The way of density adjustment and specific dosage of NaCl and hcoona were established to inhibit the formation of salt crystallization. HTA solid acid and JCI are used to counteract each other to reduce the corrosion of casing steel. The core displacement results show that the permeability recovery value of carbonate core after completion fluid treatment can reach 97.54%, and that of sandstone core after treatment can reach 114.7%. Moreover, the completion fluid system also has a certain acidizing effect, which can not only clean and remove the plugging, but also serve as the early induction of acidizing and stimulation.

New Fracture Diagnostic Test Delivers Tight Reservoir Data in 2 Hours or Less, Bolsters Future of Engineered Completions

One of the grand challenges facing the oil and gas industry’s global quest to improve the potential of tight reservoirs involves designing horizontal-well completions that match the often-complex heterogeneity of the target formations. This sums up the general concept most call the “engineered completion.” In theory, tailoring a stimulation job to the varying rock properties found along the lateral section of a horizontal wellbore should result in better production for less capital. In practice, the industry has never attempted to do this on a meaningful scale. Among other reasons, the detailed subsurface data required to shake the bonds of geometric, or “cookie cutter,” designs have long been considered too costly to gather or too time-consuming to analyze. A shift is underway though. This is thanks in part to a number of innovations that have hit the market in recent years to meet rising demand for real-time completions-monitoring services. By interpreting pressure signals and other reservoir responses, the new tools aim to give operators the competency they need to adjust fracture designs as the stimulation progresses. But there is another route to the engineered completion. It begins before the well is hydraulically fractured. This effort to predetermine different fracture-stage designs has established its own distinct arena of innovation. Behnam Zanganeh, a former research student at the University of Calgary, was part of a team that developed one of the latest approaches. It is notable in part because it requires no new technology - just new ways of thinking about some old ideas. In a paper published last month during the virtual Unconventional Resources Technology Conference, Zanganeh and his fellow petrotechnical researchers showed how multiple points in a wellbore can be tested for different reservoir-quality parameters quickly and simply relative to traditional methods (URTeC 2838). This is done by combining and fundamentally altering a test known for being slow: the diagnostic fracture injection test (DFIT). The biggest change it calls for is to start flowback after the injection cycle for flowback analysis (FBA), thus eliminating the lengthy falloff cycle associated with the DFIT. The paper outlines a validation study done with Sydney-based Origin Energy which used the blended DFIT-FBA method in a vertical open hole to test two previously untested horizons in the Beetaloo Basin, a frontier unconventional gas play in the center of Australia’s Northern Territory. The results were integrated into the models Origin ultimately used to select its landing target for its subsequent horizontal program.

Real-Time Formation-Face-Pressure Analysis Improves Acid-Fracturing Operations

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 194351, “Real-Time Analysis of Formation-Face Pressures in Acid-Fracturing Treatments,” by Vibhas Pandey, SPE, and Robert Burton Jr., SPE, ConocoPhillips, and Kay Capps, Capsher Technology, prepared for the 2019 SPE Hydraulic Fracturing Technology Conference and Exhibition, The Woodlands, Texas, USA, 5–7 February. The paper has not been peer reviewed. Knowledge of formation-face pressures is critical to the success of hydraulic-fracturing treatments, especially in multistage and multiple-cluster-type horizontal-well completions. This knowledge can help in evaluating the effectiveness of acid-fracturing treatments in dynamic mode and also can enable and improve real-time decision-making during treatment execution. This paper contains a detailed discussion of methods and a software tool that has been developed to generate information that predicts formation-face pressures in real time with the help of live bottomhole-pressure data. Introduction Acid-fracturing treatments combine the basic principles of hydraulic fracturing and acid-reaction kinetics to stimulate acid-soluble formations. Unlike propped fracturing treatments, in which a viscous pad is followed by slurry-laden fluid that assists in keeping the fracture propped open to create a conductive flow path for formation fluids, the fracture conductivity in acid fracturing is generated by dissolving the formation face to create an uneven surface on the fracture walls. Multiple pad and acid stages are pumped during the course of the treatment to create a high-conductivity fracture. The acid stage then fingers through the pad and the open fracture to create differentially etched patterns on the fracture walls. The uneven, etched surfaces prevent the fracture from closing completely once the hydraulic pressure is removed, leading to a highly conductive pathway to enhance hydrocarbon flow. Once the acid contacts the formation, the bottomhole treating pressure recedes quickly, and, as acid spending continues, the effective bottomhole pressures can fall below fracture-closure stresses. Not all loss of pressure is a result of acid spending alone. The fluid fingering among fluids of highly contrasting viscosities also can result in such drops. However, the stress relief that results from acid spending dominates this behavior. Pumping additional acid in these cases only results in near-well acid or mineral reactions, which do not extend fracture penetration and may increase wellbore-integrity risks. Unfortunately, without a good estimation of effective fracture pressures, determination of when the fracture-treatment pressure dips from above closure stress to below closure stress is difficult. Determination of this critical transition was a primary driver of the study that led to the creation of a tool that can assist in determining the real-time treating pressures at the entry of the fracture during stimulation treatments. Several acid-fracturing treatments were analyzed using the tool, leading to important conclusions related to fracture-propagation modes, acid-exposure times, and effectiveness of given acid types.

Reservoir forming conditions and key exploration and development technologies for marine shale gas fields in Fuling area, South China

Although shale gas resources are abundant in China, commercial discoveries have not been made before the discovery of Fuling Shale Gas Field. SINOPEC has done lots of theoretical and technological studies on marine shale gas development in China. Research shows shale gas has dynamic accumulations with early preservation and late reconstruction and proposes high-quality shale developed in deep-water shelf as the base and good preservation conditions as the key factor for shale gas accumulation. Key technologies and facilities were developed for geophysical survey of shale gas, design and optimization of shale gas development, drilling and completion of horizontal wells, and fracturing stimulation. As the first and largest shale gas field in China, the discovery and successful development of Fuling Shale Gas Filed has made China the first country to achieve large-scale development of shale gas after North America. By August 2017, Fuling Shale Gas Field had declared 6008.14 × 108 m3 proven reserves, 76.8 × 108 m3 production capacity and 133.9 × 108 m3 cumulative production. The construction of Fuling Shale Gas Field with high level, high speed and high quality has been a good example of shale gas development in China. Its successful experiences can be used to other fields and play an important role in optimizing energy structure and improving environment.

Integrated Completion Sensitivities for Horizontal-Well Design in the Vaca Muerta

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 185499, “Fracturing-to-Production Integrated Completion Sensitivities for Horizontal-Well Design in the Vaca Muerta Shale,” by S. Pichon, F. Cafardi, G.D. Cavazzoli, A. Diaz, and M.R. Lederhos, Schlumberger, prepared for the 2017 SPE Latin America and Caribbean Petroleum Engineering Conference, Buenos Aires, 17–19 May. The paper has not been peer reviewed. The boom in organic shale plays has revealed the critical need to size hydraulic-fracture treatments correctly to achieve commercial success. The right balance must be found between the cost of fracturing and the additional production achieved by increasing the formation-to-wellbore contact area. The complete paper examines a range of completion scenarios to evaluate the relationship between hydraulic-fracture design, production, and well profitability by use of numerical simulations to guide completion of horizontal wells in Argentina’s Vaca Muerta Shale. Introduction The Vaca Muerta Shale is the source rock of most of the producing formations in the Neuquén Basin, with high potential as a standalone reservoir. The first well aiming at testing production from the play was drilled and completed in 2010, and, at the end of 2016, the production from the formation involved more than 600 wells. Well-construction practices have moved from creating vertical wells to creating horizontal wells. In any organic shale play, completion has a significant weight in the total well cost and must be sized adequately. Completion design is composed of the volume and number of hydraulic fractures to be created along the lateral, and it must be engineered according to the specific features of each formation. One of the principal features of an organic shale reservoir is the absence of commercial production unless the well is hydraulically fractured. Enhancing the contact area between the formation and the wellbore with hydraulic fractures compensates for the extremely low permeability of these formations. Multiple factors, including geomechanics and stress direction, drive the geometry of the hydraulic fractures. However, it must be noted that most organic shale reservoirs are overpressured. This factor tends to drive the stresses up and reduce their horizontal anisotropy. Besides the hydraulic-fracture geometry, production is also the result of the hydrocarbon volume in place and the interaction of the flow capacities between the reservoir and the created network of conductive fractures. Therefore, the size of this surface of exchange created by the hydraulic fractures has a critical effect on the level and dynamics of the production profile. Finally, economics is the balance between total well cost and production. The completion design affects both production and total well cost, making it a critical parameter. Fracturing-to-Production Integrated Work Flow Work-Flow Requirements. With the primary objective being the combined evaluation of completion design, hydraulic-fracture geometry, production, and economics, the methodology must allow an explicit description, at either the input or output level, of each one of the aforementioned parameters. The fracturing-to-production work flow fits this purpose and is proposed for this study. The work flow has been implemented successfully in the Vaca Muerta and various other shale plays.

Friction-Load Redistribution for Extended-Reach- and Horizontal-Well Completions

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IADC/SPE 178905, “Friction-Load Redistribution for Robust and Cost-Efficient Design of Extended-Reach- and Horizontal-Well Completions,” by A.R. McSpadden, SPE, and R. Trevisan, SPE, Altus Well Experts, prepared for the 2016 IADC/SPE Drilling Conference and Exhibition, Fort Worth, Texas, USA, 1–3 March. In horizontal and extended-reach wells in which long completions are run into highly deviated or lateral zones, large compression loads arise because of running friction. These loads remain locked in the string when the packer or cement sets. Dissipation of friction caused by string vibrations and movements redistributes these friction loads between the wellhead and the packer or the top of the cement. A numerical approach is presented to calculate the redistributed friction load so that an accurate initial tubing load is implemented in the tubular-stress analysis. Introduction The long lateral wells in modern shale developments provide new motivation to better understand and model the effect of friction in casing and tubing design. The multiple-barrier approach and modern design techniques compare favorably with previous generations of well construction. Even so, the root-cause failure analysis of individual subsurface components such as tubing, connections, or packers is difficult. The multizone- fracture-stimulation techniques common to shale developments combine the multiple challenges of long lateral zones with associated friction-induced compression loads and cyclic thermal loading from successive stimulation, flowback, and production. An important motivation for understanding the effect of redistribution of locked-in friction loads is the increasing application of onetrip multistage completions and intelligent-well-system completions in unconventional- reservoir field developments. In extended-reach wells, as the long laterals grow longer and more-expensive equipment is run out farther into the reservoir-contact area, design requirements will become increasingly challenging. It can be argued that these considerations are not as important for cemented completions or where the production casing is the effective operational conduit. However, even for production-casing fracture stimulations or even production, loads below the top of the cement cannot necessarily be disregarded. Also, the planned top-of-cement depth may not be realized. Hence, much more of the casing may be uncemented than in the original plan.

Pressure Drop Calculation Models of Wellbore Fluid in Perforated Completion Horizontal Wells

Perforated completion is a main method of horizontal well completion. Based on the mass conservation equation, the momentum conservation equation and the variable mass flow in the horizontal wellbore, pressure drop calculation models of the wellbore fluid are established in perforated completion of horizontal wells. The results of calculation and analysis show that the frictional pressure drop, acceleration pressure drop and mixing pressure drop have different effects on total pressure drop of the wellbore fluid, and the frictional pressure drop plays a major role while the acceleration pressure drop and mixing pressure drop have little influence. The liquid viscosity, production and horizontal wellbore length also have different effects on various kinds of pressure drop. When liquid viscosity is smaller and the length of the horizontal wellbore is shorter, the effects of the acceleration pressure drop and mixing pressure drop cannot be neglected. The theoretical basis and the calculation model of the variable mass flow pressure drop of horizontal wellbore are provided.

Selection of the optimal completion of horizontal wells with multi-stage hydraulic fracturing of the low-permeable formation, field C

At the moment, many fields of Western Siberia are in the later stages of development. In this regard, the multilayer fields are actually involved in the development of hard to recover reserves by conducting well interventions. However, most of these assets may not to be economical profitable without application of horizontal drilling and multi-stage hydraulic fracturing treatment. Moreover, location of frac ports in relative to each other, number of stages, volume of proppant per one stage are the main issues due to the fact that the interference effect could lead to the loss of oil production. The optimal arrangement of horizontal wells with multi-stage hydraulic fracture was defined in this paper. Several analytical approaches have been used to predict the started oil flow rate and chose the most appropriate for field C reservoir J1. However, none of the analytical equations could not take into account the interference effect and determine the optimum number of fractures. Therefore, the simulation modelling was used. Finally, the universal equation is derived for this field C, the reservoir J1. This tool could be used to predict the flow rate of the horizontal well with hydraulic fracturing treatment on the qualitative level without simulation model.

Scoring completion effectiveness in unconventional horizontal wells using 3D seismic attributes

Using a multihorizontal well-completion pilot in an unconventional oil field in the Lower 48 (contiguous United States) Midcontinent, a workflow is proposed to evaluate the effectiveness of horizontal-well completions through 3D surface-seismic attributes and microseismic data. Three-dimensional surface seismic is often continuous over unconventional fields and provides a measurement in areas where no other data are available. In addition, microseismic is the only geophysical data that allows us to “see” the apparent hydraulic-fracture zone around a wellbore. Using these two geophysical tools integrated with engineering and geologic data such as image logs, total proppant, number of stages, estimates of fracture length and height, permeability, chemical tracers, and production rates, a “geophysical completion scorecard” is developed to evaluate a multiwell horizontal pilot and apply it to additional wells drilled outside the pilot in an effort to predict their completion effectiveness. A postdrill review of production rates in those wells shows good correlation to the scorecard's predictions of completion effectiveness.

Simultaneous initiation and growth of multiple radial hydraulic fractures from a horizontal wellbore

Multi-stage fracturing is the current preferred method of completion of horizontal wells in unconventional hydrocarbon reservoirs. Its core component consists in simultaneously initiating and propagating an array of hydraulic fractures. We develop a numerical model for the initiation and growth of an array of parallel radial hydraulic fractures. The solution accounts for fracture growth, coupling between elastic deformation and fluid flow in the fractures, elastic stress interactions between fractures and fluid flow in the wellbore. We also take into account the presence of a local pressure drop (function of the entering flow rate) at the connection between the well and the fracture, i.e., a choke-like effect due to current well completion practices, also referred to as entry friction. The partitioning of the fluid into the different fractures at any given time is part of the solution and is a critical indicator of simultaneous (balanced fluid partitioning) versus preferential growth. We validate our numerical model against reference solutions and a laboratory experiment for the initiation and growth of a single radial hydraulic fracture. We then investigate the impact of stress interaction on preferential growth of a subset of fractures in the array. Our results show that a sufficiently large local entry friction provides a strong feedback in the system and thus can counteract elastic stress interaction between fractures, thereby ensuring simultaneous growth. We propose a dimensionless number capturing the competition between stress interaction and local entry friction. This dimensionless number is a function of rock properties, fracture spacing and injection parameters. We verify that it captures the transition from the case of simultaneous growth (entry friction larger than interaction stress) to the case of preferential growth of some fractures (interaction stress larger than entry friction). We also discuss the implication of these results for multi-stage fracturing engineering practices.

Economic Optimization of Horizontal-Well Completions in Unconventional Reservoirs

Summary Extrapolation of conventional paradigms to unconventional reservoirs can lead to disappointment and poor performance. Careful analysis of the reservoir and application of the correct stimulation design are critical when dealing with marginally economic developments. This approach includes adequate characterization of the reservoir and an understanding of the factors that control flow capacity and deliverability. One of the biggest practical problems with unconventional-stimulation-design optimization is estimating post-fracture rate, production decline, and ultimate recovery. Without a realistic prediction of the decline resulting from a given completion, it is impossible to assign value to one design over another and equally impossible to optimize the treatment for whichever goal is sought, either acceleration of recovery or increase in reserves. It is often the first—inadequate reservoir characterization—that leads to the second—unrealistic post-treatment predictions. For instance, assuming that core-derived permeability fully represents the reservoir's total flow capacity or that stimulated reservoir volumes represent the effective producing volumes can lead to incorrect diagnosis of the reservoir capability and, consequently, can lead to an inefficient treatment design. This paper presents methods for production forecasting that give reasonable post-treatment predictions that have been found useful for economic planning. The proposed methodology, backed by field observations and laboratory work, provides an economically viable plan for optimizing lateral length, fracture spacing, and treatment design. The methodology focuses on the post-stimulation effective reservoir volume. Results show that increasing apparent fracture length rarely impacts long-term recovery. Likewise, adding more fractures within the same reservoir volume may increase early-time production rate (initial production) and decline rate, without contacting more reservoir volume or adding to long-term recovery. Such practices lead to acceleration of reserves recovery, which has economic value and should be considered in the design process, but does not increase the ultimate recovery of the well once a sufficient number of contributing fractures are in place. The economically preferred completion designs may be more driven by the net present value derived in the first 5 years of production rather than the ultimate recovery of the well. This early 5-year period represents most of the useful economic life of the well, can be estimated more accurately from early performance, and is a good benchmark for completion optimization.

Economic Optimization of Horizontal-Well Completions in Unconventional Reservoirs

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 168612, ’Economic Optimization of Horizontal-Well Completions in Unconventional Reservoirs,’ by R.D. Barree, SPE, Barree & Associates; S.A. Cox, SPE, PetroEdge Energy III; J.L. Miskimins, SPE, and J.V. Gilbert, SPE, Barree & Associates; and M.W. Conway, SPE, Core Laboratories, prepared for the 2014 SPE Hydraulic Fracturing Technology Conference, The Woodlands, Texas, USA, 4-6 February. The paper has not been peer reviewed. This paper presents methods for production forecasting that give reasonable post-treatment predictions that have been found to be useful for economic planning. The proposed methodology provides an economically viable plan for optimizing lateral length, fracture spacing, and treatment design. The methodology focuses on the post-simulation effective reservoir volume. Results show that increasing apparent fracture length rarely affects long-term recovery. Likewise, adding more fractures within the same reservoir volume may increase early-time production rate and decline rate without contacting more reservoir volume or adding to long-term recovery. Introduction Industrywide, there appear to be several basic assumptions that govern expectations about recovery generated through horizontal-well stimulation in unconventional reservoirs. Depending on the basic belief system applied, dramatically different, even diametrically opposed, recommendations result. The first belief is that core-derived permeability values, usually from crushed samples, represent overall reservoir flow capacity accurately. This assumption frequently controls post-treatment expectations regarding treatment size, spacing of perforation clusters (fracture-initiation points), or number of treatment stages and most significant aspects of completion design. However, core permeabilities do not represent the overall reservoir flow capacities, something that diagnostic fracture injection tests (DFITs) or production analysis does achieve by measuring the integrated-system permeability, including any secondary fracture enhancement, including existing natural fractures and shear and extensional fracture enhancement developed during the stimulation process. The assumption that crushed-core-derived matrix permeability describes the system flow capacity is generally accompanied by the industry’s second belief, that created or seismically imaged fracture length represents the effective flowing length of the hydraulic fractures. The combination of these two beliefs is used by the industry to explain the observed production behavior in many models. In other words, belief in one requires belief in the other. However, field observations and many years of laboratory work strongly support the conclusion that effective fracture length is much smaller than the created or imaged length and that fracture cleanup is driven by the reservoir flow capacity. In very-low-permeability and low-pressure systems, the effective fracture length is limited by cleanup (flowing length) rather than by conductivity.

Innovative Geosteering Technology in Multilateral Wells

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 24002, ’Innovative Geosteering Technology Used in Drilling Smart Multilateral Wells, Kuwait,’ by T. El Gezeery, A. Aziz Ismael, K. Al-Anezi, G.S. Padhy, Fawaz Al Saqran, A. Abdul-Latif, and J. Silambuchelvan, Kuwait Oil Company, and J. Estarabadi and G. Ferroni, Geolog International, prepared for the 2013 Offshore Technology Conference, Houston, 6-9 May. The paper has not been peer reviewed. Copyright 2013 Offshore Technology Conference. Reproduced by permission. The Burgan reservoir in Kuwait has the potential for premature water breakthrough, leaving behind bypassed zones of oil. The placement and completion of horizontal wells in such reservoirs is a challenge necessitating a collaborative approach from petroleum geoscience, reservoir engineering, and petroleum engineering. This paper describes placement of horizontal wells in this kind of heterogeneous reservoir through an integrated approach. Introduction The Minagish field was discovered in 1959 and is located in the southwestern part of Kuwait. It contains several reservoir intervals in its stratigraphic column, varying from Early Jurassic to Late Cretaceous. The field is situated 12 km northwest from the West Umm Gudair field (Fig. 1). The field has been penetrated by more than 180 wells. The field structure of the Burgan formation is a closed elongated asymmetrical anticline oriented in a north/south direction. The top of the Burgan structure is located at approximately 5,500-ft true vertical depth (TVD) minus the elevation above mean sea level of the depth reference point of the well. Regional Geology. The Burgan formation consists of a lower braided river system with stacked sand bodies. The sediment ranges from fine to medium grain sizes, and the porosities are high enough for lateral migration. On top of the upper Burgan channels, the sediments are generally finer but still retain a fluvial character. The amount of shale is higher. The marsh and tidal sediments, which consist of fine sands, silty sands, and sandy silts, seem to be of lower connectivity for vertical migration. The porosity is relatively low (between 15 and 18%), and the minimum of the measured permeability is close to 1 md for these layers. It seems that these shaly sediments can act as permeability barriers for vertical migration, but oil is observed in all channels and has been able to reach the reservoirs. This complex channel geometry makes these reservoirs the most challenging clastic reservoirs in the Minagish field.

Study on Drilling and Completion Techniques of Horizontal well for Coalbed Methane

Due to the unique reservoir characteristics of the coalbed methane (CBM) in China, many technical problems have to be studied and solved in the development of horizontal wells for CBM. In this paper, based on the V-type wells, we have summarized the many techniques involved in Drilling and completion of horizontal well for CBM in Binchang mining area, such as leakage protection and sealing, geosteering while drilling, remote connection, variable density cementing, Coal seam cavitation, fiberglass casing running into the well, and etc. It is pointed out that the air foam under-balance drilling will be the development direction for coalbed methane drilling technology.

Study of Optimization Method for Variable-Density Completion of Horizontal Well

Based on Landman variable density perforation model, a horizontal well variable-density completion coupling model is derived under non-homogeneous formation conditions. And an actual well is taken for example to calculate the production fluid profile of horizontal well under different perforation densities. The results show that the production fluid profile of the high and low permeability section tends to be even with the decrease of the perforation density of the high-permeability section. Based on the coupling model, optimization methods for the variable-density completion of horizontal well under uneven stratum conditions are put forward. The production fluid profiles of optimized perforation model, actual perforation model, and even perforation model are compared. According to the results, the horizontal well corresponding to the optimized perforation model is with the most balanced inflow profile.

An Integrated Approach To Design Completions for Horizontal Wells for Unconventional Reservoirs

Summary This paper presents a comprehensive and integrated workflow to design completions for a heavy-oil recovery process that involves injection and production through the same well. Unlike in traditional completion design, the transient effects are particularly important to consider while analyzing the long-term performance for these types of completions to capture the effect of variations or uncertainties in reservoir and fluid-flow characteristics over time. The proposed integrated workflow involves initial screening and selection of flow-restricting completions that can meet the desired injection and production performance based on a detailed wellbore hydraulics modeling tool. A select few completions are then analyzed for longer-term performance using a reservoir simulator that couples the flow-restricting nature of completions with flow in the reservoir. The use of best-in-art wellbore hydraulics model and reservoir simulator in a staged process yields an effective way to assess and optimize the completion design for these wells in a reduced time span. The workflow disclosed here can be used to design effective completions for a broad class of cyclic liquid-injection methods for heavy-oil resources.